In the oil and gas industry, there is considerable value in the ability to monitor the flow properties of fluid in a well. Many wells consist of several hydrocarbon-producing zones that vary in permeability and are perforated or otherwise left open to permit production. It is desirable to obtain flow data from each of these zones to make operational decisions regarding production rate, stimulation, remediation, and other issues that arise in well operation. In addition to production flow data, injection flow data is also valuable as it can reveal how much fluid is being injected into a particular zone of and how this fluid is being absorbed by the formation.
To address this need, the industry has developed an array of “intelligent well” technologies that are designed to measure flow properties in a producing well. Frequently measured properties include but are not limited to temperature, pressure, composition, and flow rate. Some measurement tools are installed in the well permanently for long term monitoring while others are run into the well during an intervention to obtain a temporary measurement. Despite advances in these intelligent well technologies, the tools currently available are limited by technical challenges. Some challenges include building a sensing device that is durable enough to withstand the harsh conditions of the downhole environment, providing power to such a device, increasing reliability of downhole sensing systems, and developing a tool that measures the properties of the flow in the wellbore without interfering with the production. Although numerous downhole gauges for measuring temperature, pressure, and other properties have been developed, discrete measurements at several points in the well only reveal limited details about the flow conditions downhole. Ideally, an operator would like to obtain a real time continuous profile of the flow properties along the length and circumference of the wellbore as well as radially into the formation.
A promising new development in the area of downhole sensing is distributed temperature sensing or DTS. See James J. Smolen and Alex van der Spek, Distributed Temperature Sensing: A DTS Primer for Oil & Gas Production, Shell International Exploration and Production B.V. (May 2003). A DTS system works by utilizing a distributed sensor as the sensing mechanism. Once the distributed sensor is installed in the well, a pulse of laser light is sent along the fiber so that it collides with the lattice structure and atoms of the fiber causing them to emit small bursts of light, which are “backscattered” or returned to the beginning of the fiber. These bursts of light are returned at slightly shifted frequencies. Because of this frequency shift, the backscattered light provides information, which can be used to determine the temperature at the point from which the backscatter originated. Because the velocity of light is constant, one can determine the distance from the surface to the point where the temperature was recorded using the elapsed travel time of the light pulse. By continually monitoring backscattered light, one can obtain a continuous profile of temperature along the length of the fiber.
US Patent Application US 2005/0034873 A1 (hereafter Coon) discloses a method for placing a fiber optic sensor line in a wellbore. The method in Coon includes providing a tubular in the wellbore, the tubular having a first conduit operatively attached thereto, whereby the first conduit extends substantially the entire length of the tubular. The method further includes aligning the first conduit with a second conduit operatively attached to a downhole component and forming a hydraulic connection between the first conduit and the second conduit thereby completing a passageway for the fiber optic sensor line to be urged through with a fluid pump and a hose. Although this method can provide flow data along the entire length of the well, the measurements are limited to a single side of the wellbore. Ideally, operators would like to obtain a complete profile of the inflow and outflow of the well along its depth and circumference.
U.S. Pat. No. 5,804,713 (hereafter Kluth) discloses an apparatus for installation of fiber optic sensors in wells. Kluth discloses an apparatus with a first channel containing at least one sensor location arrangement so that at least one sensor can be pumped through the first channel to the sensor location arrangement with at least one turn such that the physical disposition of the sensor after it has been pumped to the sensor location arrangement is not linear, and the turn comprises a loop of hydraulic conduit. Essentially, the sensor is installed by pumping the line through a hydraulic conduit, which is wrapped around the production tubing. Some parts of the conduit allow the fiber optics cable to be wrapped circumferentially around the pipe while others provide a linear configuration. Generally, a low viscosity fluid must be maintained at a particular flow rate in order to locate the fiber at a specific sensor location. In some applications, a load is applied to the fiber optic line, which could cause potential damage to its sensing capabilities.
U.S. Pat. No. 6,959,604 (hereinafter Bryant) discloses an apparatus for measuring an unsteady pressure within a pipe comprising an optical sensor including at least one optical fiber disposed circumferentially around at least a portion of a circumference of the pipe. The optical fiber provides an optical signal indicative of the length of the fiber. An optical instrument determines a signal indicative of the unsteady pressure in response to the optical signal. In this system the fiber is wrapped circumferentially around the outside of the pipe.